The exploration and production of hydrocarbons from subsurface formations ultimately requires a method to reach and extract the hydrocarbons from the formation. Referring to FIG. 1, a typical oil or gas well 10 includes a borehole 12 that traverses a subterranean formation 14 and includes a wellbore casing 16. During operation of the well 10, a drill pipe 18 may be positioned within the borehole 12 in order to inject fluids such as, for example, drilling mud into the wellbore. As will be recognized by persons having ordinary skill in the art, the end of the drill pipe 18 may include a drill bit and the injected drilling mud may be used to cool the drill bit and remove particles drilled away by the drill bit. The fluid then circulates back up the annulus formed between the borehole wall and the drill bit, taking with it the cuttings from the drill bit and clearing the borehole. A mud tank 20 containing a supply of drilling mud may be operably coupled to a mud pump 22 for injecting the drilling mud into the drill pipe 18.
Traditionally fluid is selected such that the hydrostatic pressure applied by the fluid is greater than surrounding formation pressure, thereby preventing formation fluids from entering into the borehole 12. It also causes the fluid to enter into the formation pores, or “invade” the formation 14. Further, some of the additives from the pressurized fluid adhere to the formation walls forming a “mud cake” on the formation walls. This mud cake helps to preserve and protect the formation prior to the setting of casing in the drilling process. The selection of fluid pressure in excess of formation pressure is commonly referred to as over balanced drilling.
The annulus 24 between the casing 16 and the drill pipe 18 may be sealed in a conventional manner using, for example, a rotary seal 26. In order to control the operating pressures within the well 10 within acceptable ranges, a choke 28 may be operably coupled to the annulus 24 between the casing 16 and the drill pipe 18 in order to controllably bleed off pressurized fluidic materials out of the annulus 24 back into the mud tank 20 to thereby create back pressure within the borehole 12. The clean, returned fluid flow is measured to determine fluid losses to the formation as a result of fluid invasion. The returned solids and fluid (prior to treatment) may be studied to determine various formation characteristics used in drilling operations. Once the fluid has been treated in the mud pit, it is then pumped out of the mud pit and re-injected into the top of the drill string again. This overbalanced technique relies primarily on the fluid density and hydrostatic force generated by the column of fluid in the annulus to generate pressure. By exceeding the formation pore pressure, the fluid is used to prevent sudden releases of formation fluid to the borehole, such as gas kicks. Where such gas kicks occur, the density of the fluid may be increased to prevent further formation fluid release to the borehole. However, the addition of weighting additives to increase fluid density (a) may not be rapid enough to deal with the formation fluid release and (b) may exceed the formation fracture pressure, resulting in the creation of fissures or fractures in the formation, with resultant fluid loss to the formation, possibly adversely affecting near borehole permeability. In such events, the operator may elect to close the blow out preventors (BOP) below the drilling rig floor to control the movement of the gas up the annulus. The gas is bled off and the fluid density is increased prior to resuming drilling operations.
The use of overbalanced drilling also affects the selection of casing during drilling operations. The drilling process starts with a conductor pipe being driven into the ground, a BOP stack attached to the drilling conductor, with the drill rig positioned above the BOP stack. A drill string with a drill bit may be selectively rotated by rotating the entire string using the rig kelly or a top drive, or may be rotated independent of the drill string utilizing drilling fluid powered mechanical motors installed in the drill string above the drill bit. As noted above, an operator may drill open hole for a period until such time as the accumulated fluid pressure at a calculated depth nears that of the formation fracture pressure. At that time, it is common practice to insert and hang a casing string in the borehole from the surface down to the calculated depth. A cementing shoe is placed on the drill string and specialized cement is injected into the drill string, to travel up the annulus and displace any fluid then in the annulus. The cement between the formation wall and the outside of the casing effectively supports and isolates the formation from the well bore annulus and further open hole drilling is carried out below the casing string, with the fluid again providing pressure control and formation protection.
FIG. 2 is an exemplary diagram of the use of fluids during the drilling process in an intermediate borehole section. The top horizontal bar represents the hydrostatic pressure exerted by the drilling fluid and the vertical bar represents the total vertical depth of the borehole. The formation pore pressure graph is represented by line 40. As noted above, in an over balanced situation, the fluid pressure exceeds the formation pore pressure for reasons of pressure control and hole stability. Line 42 represents the formation fracture pressure. Pressures in excess of the formation fracture pressure will result in the fluid pressurizing the formation walls to the extent that small cracks or fractures will open in the borehole wall and the fluid pressure overcomes the formation pressure with significant fluid invasion. Fluid invasion can result in reduced permeability, adversely affecting formation production. The annular pressure generated by the fluid and its additives is represented by line 44 and is a linear function of the total vertical depth. The pure hydrostatic pressure that would be generated by the fluid, less additives, i.e., water, is represented by line 46.
In an open loop fluid system described above, the annular pressure seen in the borehole is a linear function of the borehole fluid. This is true only where the fluid is at a static density. While the fluid density may be modified during drilling operations, the resulting annular pressure is generally linear. In FIG. 2, the hydrostatic pressure 46 and the pore pressure 40 generally track each other in the intermediate section to a depth of approximately 7000 feet. Thereafter, the pore pressure 40 increases. This may occur where the borehole penetrates a formation interval having significantly different characteristics than the prior formation. The annular pressure 44 maintained by the fluid is safely above the pore pressure prior to the increase. In the depth below the pore pressure increase, the differential between the pore pressure 40 and annular pressure 44 is significantly reduced, decreasing the margin of safety during operations. A gas kick in this interval may result in the pore pressure exceeding the annular pressure with a release of fluid and gas into the borehole, possibly requiring activation of the surface BOP stack. As noted above, while additional weighting material may be added to the fluid, it will be generally ineffective in dealing with a gas kick due to the time required to increase the fluid density as seen in the borehole.
Fluid circulation itself also creates problems in an open system. It will be appreciated that it is necessary to shut off the mud pumps in order to make up successive drill pipe joints. When the pumps are shut off, the annular pressure will undergo a negative spike that dissipates as the annular pressure stabilizes. Similarly, when the pumps are turned back on, the annular pressure will undergo a positive spike. This occurs each time a pipe joint is added to or removed from the string. It will be appreciated that these spikes can cause fatigue on the borehole cake and could result in formation fluids entering the borehole, again leading to a well control event.
In contrast to open fluid circulation systems, there have been developed a number of closed fluid handling systems. A closed system is used for the purposes of underbalanced drilling, i.e., the annular pressure is less than that of the formation pore pressure. Underbalanced drilling is generally used where the formation is a chalk or other fractured limestone and the desire is to prevent the mud cake from plugging fractures in the formation. Moreover, it will be appreciated that where underbalanced systems are used, a significant well event will require that the BOPs be closed to handle the kick or other sudden pressure increase.
Thus it would be an improvement to the art to have a system that can manage pressure in the bore hole throughout drilling operations.